Biogas typically refers to a mixture of different gases produced from the breakdown of organic matter in the absence of oxygen in an anaerobic digestion process. Biogas can be produced from raw materials such as agricultural waste, manure, municipal waste, plant material, sewage, green waste or food waste. Biogas typically comprises as the main components 50-70% of methane (CH4) and 20 to 50% carbon dioxide (CO2), with lower levels of other components such as N2 and O2, up to 5,000 ppm or more of hydrogen sulfide (H2S), siloxanes, up to 1,000-2,000 ppm of volatile organic compounds (VOC's), and is saturated with water. Biogas also includes landfill gas (LFG), which is derived from solid waste landfills that decompose to the organic waste with time, and microbe digestion of the variety of organic waste to produce methane and CO2 with the wide variety of decomposition products above. In either case biogas includes high concentrations of methane and carbon dioxide, water vapor, and lesser concentrations of VOC's and other contaminants.
Specifically, digester biogas (digester gas) or landfill gas is a type of renewable energy. Methane is commonly known as natural gas and is valuable commercial commodity as a combustible fuel for supplying energy, and also as a raw material in many industrial significant processes. Thus, it is very desirable from an economic viewpoint to capture the methane from landfill or digester gas. Especially since biogas is a renewable source and not a fossil fuel.
If digester and landfill exhaust gas is not recovered, the methane escaping into ambient air presents a considerable source of air pollution. Accordingly, it is further desirable to prevent the methane emissions produced from the anaerobic digestion for environmental protection purposes. Traditionally, digester and landfill exhaust gas has been prevented from escaping to the environment by burning it in an open flame incinerator such as a flare stack. This process is inefficient. Consequently, a fraction of the methane and other obnoxious contaminants in the exhaust gas survive to pollute the ambient air. Also, common flare stack operations are a waste of the useful energy held by the methane in the exhaust gas.
Other conventional methods of recovering methane from digester and landfill exhaust gas and other sources of crude natural gas have been developed. These include gas separation processes in which the useful methane is separated from the other components of the source gas. Favored conventional gas separation processes typically utilize adsorption-regeneration technology, in which the crude gas is passed through an adsorbent material that passes selected components through the bed and adsorbs and rejects others. For example, pressure swing adsorption (“PSA”) or Thermal Swing Adsorption (“TSA”) technologies involve selectively adsorbing contaminants of crude gas onto adsorbent particles and allowing the so-called sweetened gas to pass through the PSA/TSA units.
Unfortunately, the adsorbent particles ultimately become saturated with the contaminants and lose ability to adsorb beyond a maximum amount. Before more contaminants can be removed from the crude, the adsorbent particles must be regenerated. This normally involves exposing the saturated particles to high temperatures and/or low pressures, and regeneration with fluids that have low concentrations of the contaminants to promote desorption of the contaminants from the particles. For example, TSA requires a supply of heat energy to heat the regeneration gas and PSA requires a supply of clean, usually low pressure gas. Additionally, adsorption-regeneration technology normally also requires support facilities for removal of water vapor, and pre-conditioning the crude gas, e.g., by compressing it to high pressure. Thus, it is very costly in financial and energy consumption aspects to operate conventional adsorption-regeneration technologies for recovering useful methane from crude natural gas and landfill exhaust gas.
On the contrary, membrane systems are versatile and are known to process a wide range of feed compositions and separations. With a very compact footprint and low weight, these membrane systems are well suited to offshore applications, remote locations, or for smaller flow rates. Recent developments in dew point control include membrane designs that can operate in condensing mode, as well as membranes that allow the simultaneous removal of water and heavier hydrocarbons from natural gas.
Membranes have been used for biogas treatment. Typical membrane processes such as those marketed by Air Liquide, involves the removal of H2S by a sulfur removal unit and a pretreatment to remove water and VOCs, followed by a two-stage membrane process that is dedicated to CO2 removal.
It is also well documented that glassy polymers, such as polyimide, polyamide, polysulfone, polybenzimidazole, etc., exhibit exceptional high intrinsic CO2/methane selectivity. However, the selectivity and permeance of the membranes prepared from those materials often quickly decrease once they are used for methane gas extraction in the presence of VOC's and other biogas impurities. This loss of membrane performance is caused by condensation and coating of the VOC's and siloxanes on the membrane surface. The conventional solution for this problem is to use a system including a regenerable adsorbent bed followed by a carbon trap for removing the water, siloxanes and VOCs prior to upstream of CO2 removal. Although these pretreatment systems can effectively remove heavy hydrocarbons and other components from the biogas stream, the cost of the pretreatment and/or frequent membrane replacement can be prohibitive. Indeed, the cost of the pretreatment system can be as high as 50% of the total system cost (pretreatment plus membrane).
Further, the product gas produced from digester gas and landfill gas must meet safety criteria to be injected into the utility pipeline. In particular, a common industry standard aims to comply with SoCalGas® Rule 30, which sets forth the standards for utility methane gas injection in large portion of California. Specifically, according to Rule 30, the methane gas to be delivered should have:
a) Heating Value: The minimum heating value of nine hundred and ninety (990) Btu (gross) per standard cubic foot on a dry basis, a maximum heating value of one thousand one hundred fifty (1150) Btu (gross) per standard cubic foot on a dry basis.
b) Moisture Content or Water Content: For gas delivered at or below a pressure of eight hundred (800) psig, the gas shall have a water content not in excess of seven (7) pounds per million standard cubic feet. For gas delivered at a pressure exceeding of eight hundred (800) psig, the gas shall have a water dew point not exceeding 20° F. at delivery pressure.
c) Hydrogen Sulfide: The gas shall not contain more than twenty-five hundredths (0.25) of one (1) grain of hydrogen sulfide, measured as hydrogen sulfide, per one hundred (100) standard cubic feet (4 ppm). The gas shall not contain any entrained hydrogen sulfide treatment chemical (solvent) or its by-products in the gas stream.
d) Mercaptan Sulfur: The gas shall not contain more than three tenths (0.3) grains of mercaptan sulfur, measured as sulfur, per hundred standard cubic feet (5 ppm).
e) Total Sulfur: The gas shall not contain more than seventy-five hundredths (0.75) of a grain of total sulfur compounds, measured as a sulfur, per one hundred (100) standard cubic feet (12.6 ppm). This includes COS and CS2, hydrogen sulfide, mercaptans and mono, di and poly sulfides.
f) Carbon Dioxide: The gas shall not have a total carbon dioxide content in excess of three percent (3%) by volume.
g) Oxygen: The gas shall not have an oxygen content in excess of two-tenths of one percent (0.2%) by volume, and customer will make every reasonable effort to keep the gas free of oxygen.
h) Inerts: The gas shall not contain in excess of four percent (4%) total inerts (the total combined carbon dioxide, nitrogen, oxygen and any other inert compound) by volume.
i) Hydrocarbons: For gas delivered at a pressure of 800 psig or less, the gas hydrocarbon dew point is not to exceed 45° F. at 400 psig, or at the delivery pressure, if the delivery pressure is below 400 psig. For gas delivered at a pressure higher than 800 psig, the gas hydrocarbon dew point is not to exceed 20° F., measured at a pressure of 400 psig.
These gas constituent limits restrict the concentration of gas impurities to protect pipeline integrity and ensure safe and proper combustion in end-user equipment. In particular, the hydrocarbon dew point requirement and the reduction of heavy hydrocarbons prevents unsafe formation of a liquid phase during transport. The hydrocarbon dew point is sensitive to small quantities of C6+ and VOC components. As little as 450 ppm of C8 hydrocarbon added to a lean gas can give it a cricondentherm of 50° F.
Further, the current methane market demands a high recovery rate from biogas of greater than 98% of methane. Many existing systems have been evaluated for modification, rather than costly replacements, to improve from 90-95% to at least 98% recovery of methane from biogas.
There are several known attempts to produce purified methane from biogas or natural gas.
U.S. Pat. No. 7,025,803 to Wascheck, et al. recovers high concentrations of methane from crude natural gas, and solid waste landfill exhaust gas uses a sequential combination of a pressure swing adsorber unit operation to remove volatile organic compounds from the crude feed gas mixture, followed by a membrane separation unit operation. While quite satisfactory in performance, the system does not satisfactorily handle relatively high levels of H2S. Therefore, a separate H2S removal system (such as SulfaTreat or other treatment methods) may be required for raw biogas containing relatively high H2S levels.
US 2017/0157555 to Karode, et al. teaches purification of natural gas by removing C3+ hydrocarbons and CO2 in respective first and second gas separation membrane stages to yield conditioned gas lower in C3+ hydrocarbons and CO2 in comparison to the un-conditioned natural gas. '555 is not concerned with producing biomethane, or removing VOC's (C6+ hydrocarbons), and siloxane from biogas. Further, product gas from natural gas sweetening typically contains a mixture of methane, ethane, and natural gas liquids.
U.S. Pat. No. 8,999,038 and WO 2016/107786, both assigned to Evonik Fibres GMBH, disclose a three-stage membrane process for CO2 removal using membranes with CO2/CH4 selectivity of at least 30 without any secondary compression in between the feed and permeate stages. As disclosed, this process does not simultaneously remove sufficient amounts of H2S and CO2 while achieving high methane recovery (>94%). Because the first stage permeate is not recompressed before being fed to the permeate stage, the driving force (i.e., the pressure difference between the feed and permeate sides) across the permeate stage is relatively low. A relatively low driving force necessitates a relatively greater amount of membrane surface area in both the first stage and the permeate stage, or in other words, a relatively greater number of membranes in both stages. Thus, capital costs are significantly increased. The disclosed process also requires a substantial modification if applied to an existing two-stage system. This is a very costly endeavor for customers who only wish to achieve an incremental methane recovery (in the product gas from the raw biogas) from 94% to about 98%.
U.S. Pat. No. 5,709,732 to Prasad teaches a membrane separation method for purified oxygen gas (60-90% purity) using a three-stage membrane system, wherein air is first permeated, then compressed and permeated in two subsequent membrane stages, to provide purified oxygen as a permeated gas from the third stage. Prasad does not teach or suggest a membrane system for producing methane from biogas, nor specifies the membrane composition.
U.S. Pat. No. 6,168,649 to Jensvold, et al. teaches a three membrane stage system having two compressors for purifying xenon gas from oxygen, nitrogen, carbon dioxide, or mixtures thereof, using a membrane material having high selectivity for xenon. '649 is not concerned with providing high quality methane while simultaneously removing H2S, CO2 and other impurities.
Therefore, there remains a need for processing biogas or landfill gas at low cost for green field projects or for improving an existing system in order to achieve high recovery of methane of at least 98%. There also remains a need for processing biogas or landfill gas at low cost that includes removal of acid gases such as H2S in order to produce methane gas suitable for utility pipeline delivery with minimal pretreatment.